1. Field of the Invention
The invention relates generally to offshore drilling systems which are used to drilling subsea wells. More particularly, the invention relates to a subsea pump and an associated control system for use in offshore drilling systems.
2. Background Art
In conventional offshore drilling operations from, for example, a floating drilling vessel, a large diameter marine riser (e.g., a 21 inch marine riser) generally connects surface drilling equipment on the floating drilling vessel to a blowout preventer stack connected to a subsea wellhead located on the seabed. The marine riser is generally filled with drilling fluid (or “drilling mud”) so that a total hydrostatic pressure on a formation being drilled in a wellbore is determined by the hydrostatic pressure of the mud in the drilled wellbore (below the seabed) plus the hydrostatic pressure of the mud in the marine riser (above the seabed). In many cases, the total hydrostatic pressure of the “mud column” may exceed a fracture pressure of the formation being drilled. Accordingly, a large number of casing strings may need to be placed in the wellbore to protect the formation and maintain well control. In deep water drilling operations, the total cost of installing a large number of casing strings, combined with smaller oil and gas production rates possible through reduced diameter casing, can often result in wells which are uneconomical to drill and produce.
It has been determined that an important aspect of improving the economics and well control of deep water wells lies in reducing the hydrostatic pressure of the mud in the marine riser to that of a column of seawater, while at the same time filling the wellbore with drilling mud of sufficient weight to maintain well control. Various concepts have been presented in the past for achieving this goal, and the concepts can be grouped into two categories: mud lift drilling with a marine riser and riserless drilling.
Mud lift drilling with a marine riser typically includes a dual density mud gradient system, and the density of the mud return in the riser is generally reduced so that the hydrostatic pressure of the mud column in the riser, measured at the seabed, more closely matches that of seawater. The mud in the well bore remains weighted at a higher density to maintain proper well control. For example, U.S. Pat. No. 3,603,409 issued to Watkins et al. and U.S. Pat. No. 4,099,583 issued to Maus both disclose methods of using injected gas to reduce the density of the mud column in the marine riser, thereby reducing the hydrostatic pressure of the mud in the marine riser as measured at the seabed.
Riserless drilling generally includes eliminating the riser as a mud return path and replacing it with one or more small diameter mud return lines. For example, U.S. Pat. No. 4,813,495 issued to Leach discloses a system that eliminates the need for the marine riser and, as an alternative, uses a centrifugal pump to lift mud returns from the seafloor to the surface through a mud return line. A rotating apparatus isolates the mud in the wellbore annulus from seawater as the drillstring is run into and out of the wellbore.
U.S. Pat. No. 6,102,673, issued to Mott et al. and assigned to the assignee of the present invention, discloses a dual gradient riserless drilling system that uses a pressure actuated drillstring valve to control mud free fall, rotating and non rotating subsea diverters to isolate the mud in the wellbore from fluids, such as seawater, above the wellbore, a solids control system to control the size of solids in mud return lines, and a subsea positive displacement pump actively controlled in a coordinated manner with surface equipment on a drilling vessel to maintain the volume of mud in the wellbore.
Generally, the riserless drilling is preferred over the mud lift system because riserless drilling employs a pressure barrier between the wellbore and the surrounding environment. The pressure barrier allows the wellbore to be drilled in an “underbalanced” condition where formation pressures typically exceed the pressure of the drilling mud in the wellbore. Underbalanced drilling may significantly improve the rate of penetration of a drill bit and also helps reduce the risk of formation damage.
U.S. Pat. No. 6,102,673 issued to Mott et al discloses a subsea positive displacement pump with multiple pump elements, each pump element comprising a pressure vessel divided into two chambers by a separating member and powered by a closed hydraulic system using a subsea variable displacement hydraulic pump. The subsea positive displacement pump includes hydraulically actuated valves to ensure proper valve seating in the presence of, for example, cuttings from the drill bit that are present in mud returns from the wellbore. The hydraulically actuated valves also provide flexibility in valve timing (which is typically not available with conventional spring biased check valves) and provide quick valve response in high flow coefficient (Cv) arrangements necessary for high volume pumping (e.g., substantially high flow rates).
The subsea positive displacement pump disclosed in U.S. Pat. No. 6,102,673 issued to Mott et al is controlled by a unitary control module which receives the following signals: (1) position signals from a position indicator on the separating member in each pump element, wherein the position signals are converted into volume measurements; (2) flow and pressure signals from devices on a return side of the closed hydraulic system; (3) flow signals from a supply side of the hydraulic system (usually positioned proximate the variable displacement hydraulic pump); and (4) pressure signals from a mud suction pressure transducer.
Control signals from the control module: (1) control the operation of the flow control valve on the hydraulic fluid return to ensure that the flow rate from the variable displacement hydraulic pump is equal to the flow rate returning to the hydraulic reservoir; (2) operate the two hydraulic control valves and two hydraulically actuated mud valves on each pumping element to control the pumping rate of the subsea mud pump; and (3) control the flow rate of the variable displacement hydraulic pump. The control module algorithm is designed to provide “pulsationless” flow by precisely controlling the “phasing” of the multiple pumping elements to overlap both the fill and discharge cycles of the pumping elements.
The control system is difficult to precisely adjust because it has proven difficult to accurately model both the non-linear responses of many of the hydraulic components of the system and the wellbore hydraulic characteristics over time. In practice, significant load changes from a stable pump operating condition, such as step load changes of plus or minus fifty percent, have been found to cause instability in the system. Further, the response of the variable displacement hydraulic pump to the control signals, which is adequate at low and steady pumping rates, has proven to be inadequate at higher mud pump rates (e.g., pump rates above about 4-5 strokes per minute).
The subsea pump disclosed in U.S. Pat. No. 6,102,673 issued to Mott et al generally requires that the hydraulic power source be located proximate the subsea mud pumping elements with high flow capacity (e.g., high Cv piping between the hydraulic pump and the mud pumping elements) to minimize lag in the hydraulic response. This precludes, for example, using high pressure pumps located on the floating rig as a source of hydraulic power. Moreover, because the hydraulic valves controlling the mud pumping elements in the disclosed arrangement must have a high Cv to allow the mud pumps to operate at high flow rates, the disclosed control valve arrangement may be prone to hydraulic “water hammer” effects whenever the large bore valves open or close under differential pressure during the pumping cycle, especially at high pump rates.
It would be advantageous, therefore, to design a subsea mud pump and a coordinated control system that would enable stable, efficient operation of deep water drilling systems, including riserless drilling systems. It would also be advantageous to design a control scheme that insures that bottom hole pressure (BHP) is maintained whenever drilling mud pumps are stopped, for example, to add lengths of drillpipe to the drillstring (e.g., when “making a connection”).
Finally, it would be advantageous to design a control system that can compensate for drilling mud that has some degree of compressibility, whether because of the high hydrostatic pressures encountered in deepwater subsea operations (e.g., at depths of 10,000 feet, fresh water exhibits compressibility on the order of 2.5-3%) or because of entrained gas or volatile liquids/hydrocarbons that may be present in the drilling mud leaving the wellbore.